There may be various drivers to implement Produced Water Re-Injection (PWRI). However, re-injecting produced water from the same field cannot replace the voidage created by production, especially early in the life of the field, since most of that voidage is created by hydrocarbon extraction. Thus seawater may have to be considered to "top up?? PWRI. This raises the question of what are the implications for scale control of mixing potentially incompatible brines before injection, compared to the conventional injection scenario where the mixing takes place in the reservoir.
A study was set up to consider scale management during the life cycle of four offshore fields. The available data included analysis of formation and produced water and seawater compositions, and the time evolution of the produced water - seawater split in the injection system. The tools used included thermodynamic scale prediction and reservoir simulation calculations. Thus the evolution of the scale risk over the entire water cycle - from injection, through the reservoir, to production could be evaluated.
The produced water compositions and the results of the calculations show that the scale risk at the producers is much lower than if only seawater had been injected. Calculations were also performed to identify whether bullhead application of scale inhibitor would provide adequate protection for the wells. This was important, as some of the wells are subsea completions. The clear conclusion was that any residual scale risk at the producer wells could be managed by bullhead squeezing.
However, the corollary is that the scale risk at the injectors is much higher. The trigger for scale precipitation in this scenario is brine mixing, but instead of that happening in the reservoir, here it occurs before injection. Thus the location of greatest scale risk is moved much further upstream in the flow process.
Keywords: Oilfield scale, barium sulphate, PWRI, reactive transport simulation